Wells are drilled at various depths to access and produce oil, gas, minerals, and other naturally-occurring deposits from subterranean geological formations. As wells are established it is often useful to obtain information about the well, the geological formations through which the well passes, and the fluid in the wellbore, including the fluid to be extracted from the formations. Information gathering is typically performed using tools that are delivered downhole by wireline, often referred to as wireline formation testing (“WFT”), or alternatively by tools that are coupled to or integrated into the drill string, either measuring while drilling (“MWD”) or logging while drilling (“LWD”). Tools also can be delivered downhole on pipe or tubing during Drill Stem Testing (“DST”) operations. It is often desired to collect a representative sample of formation or reservoir fluids (typically hydrocarbons) to further evaluate drilling operations and production potential, or to detect the presence of certain gases or other materials in the formation that may affect well performance.
Preservation of samples is an important aspect of well drilling. Samples may be collected at the surface or at any point downhole. Efforts are made to collect a representative sample and to maintain the sample in a representative state throughout the recovery, transfer, storage, and eventual analysis. Maintenance of the representative state is particularly significant when the sample contains trace amounts of species whose accurate determination may significantly impact operational, environmental, safety, and/or health considerations. Typical, non-limiting examples of such species include hydrogen sulfide and mercury. Hydrogen sulfide (“H2S”) is a poisonous, corrosive, and flammable gas that can occur in formation fluids, and its presence in the wellbore in significant concentrations may result in damage to wellbore components or dangerous conditions for well operators at the surface. Thus, operational considerations are greatly impacted by the location and concentration of the H2S in the produced reservoir stream. Far different procedures and equipment are required depending on whether the concentration is 2 ppm, 20 ppm, or 200 ppm and higher.
Sample vessels and long term storage vessels typically are constructed using stainless steel or austenitic nickel-chromium-based superalloys (such as those sold under the Inconel™ name) because of their availability and raw material costs, but may be constructed of more exotic and costly materials, such as cobalt or titanium. Most common metallurgies adsorb certain amounts of trace components. For example, in about a week's time, and usually less, a sample taken from a fluid stream containing 15 ppm H2S may show no H2S, when analyzed. However, when put into service, this field will deliver 15 ppm H2S. Operationally, the facility will not be properly geared to handle the actual level because none was detected in the analyzed sample. This shortcoming can have significant safety, health, environmental, operational, and cost implications.
Vessels may be coated to minimize or eliminate the adsorption and accompanying complications. Examples of such coatings include silicon-based Sulfinert™ treatments and ceramic-based Tech-12™ treatments. The coatings are usually fired at about 800° F. and leave behind about a one micron layer that fills the pore spaces available for H2S adsorption to minimize or eliminate the problem. Because of their very thin nature, these coatings are susceptible to erosion, especially during any mixing steps required for transferring or analyzing a representative sample.
Conventionally, mixing is accomplished with mixing balls or mixing rings placed inside the sample or storage vessel, such that when the container is rocked, the resulting lateral movement of the balls or rings results in the mixing of the contents. To be effective, especially within the context of viscous oils or low API value heavy oils, the mixing mechanism needs to be heavy enough to transition the sample space during the rocking action. A direct consequence of the heavy solid element moving vigorously across the inner face of a coated vessel is undesirable erosion of any applied protective coating, the loss of which results in the adsorption of certain species and subsequent analysis of a non-representative sample.
There is an ongoing need for an alternative means of mixing that is not destructive to the applied coating and that allows for analysis of representative samples. The methods and systems described herein are directed to these as well as other important ends.